There are several commercial recovery technologies that are currently used to recover in situ heavy oil or bitumen from tar sands reservoirs. In current practice, in situ technologies are used to recover heavy oil or bitumen from deposits that are buried more deeply than about 70 m below which it is no longer economic to obtain hydrocarbon by current surface mining technologies. Most commercial in situ processes can recover between about 10 and 60% of the original hydrocarbon in place depending on the operating conditions of the in situ process and the geology of the heavy oil or bitumen reservoir. The impact of variations of oil phase viscosity has been demonstrated by using detailed and advanced reservoir simulation. In addition to permeability, porosity, and oil saturation heterogeneity, oil phase viscosity variations add another complicating and sometimes process dominating feature for producing heavy oil and bitumen reservoirs.
The Steam Assisted Gravity Drainage (SAGD) is described in U.S. Pat. No. 4,344,485 (Butler) is used by many operators in heavy oil and bitumen reservoirs. In this method, two horizontal wells, drilled substantially parallel to each other, are positioned in the reservoir to recover hydrocarbons. The top well is the injection well and is located between 5 and 10 meters above the bottom well. The bottom well is the production well and typically located between 1 and 3 meters above the base of the oil reservoir. In the process, steam, injected through the top well, forms a vapour phase chamber that grows within the oil formation. The injected steam reaches the edges of the depletion chamber and delivers latent heat to the tar sand. The oil phase is heated and as a consequence its viscosity decreases and the oil drains under the action of gravity within and along the edges of the steam chamber towards the production well. In the initial stages of the process, the chamber grows vertically. After the chamber reaches the top of the reservoir, it grows laterally. The reservoir fluids, heated oil and condensate, enter the production wellbore and are motivated, either by natural pressure or by pump, to the surface. The thermal efficiency of SAGD is measured by the steam (expressed as cold water equivalent) to oil ratio (SOR), that is CWE m3 steam/m3 oil. Typically, a process is considered thermally efficient if its cumulative SOR is between 2 and 3 or lower. There are many published papers and portions of books and regulatory applications that describe the successful design and operation of SAGD. A literature review shows that while SAGD appears to be technically effective at producing heavy oil or bitumen from high quality connected reservoirs, there remains a continued need for well configurations and processes that improve the SOR of SAGD. Currently, the major capital and operating costs of SAGD are tied to the steam generation and water handling, treatment, and recycling facilities.
A variant of SAGD is the Steam and Gas Push (SAGP) process developed by Butler (Thermal Recovery of Oil and Bitumen, Gray-Drain Inc., Calgary, Alberta, 1997}, In SAGP, steam and non-condensable gas are co-injected into the reservoir, and the non-condensable gas forms an insulating layer at the top of the steam chamber. This lowers the heat losses to the cap-rock and improves the thermal efficiency of the recovery process. The well configuration is the same as the standard SAGD configuration.
Examples of literature on design and operation of SAGD in the field include: Butler (Thermal Recovery of Oil and Bitumen, Gray-Drain Inc., Calgary, Alberta, 1997), Komery et al. (Paper 1998.214, Seventh UNITAR International Conference, Beijing, China, 1998), Saltuklaroglu et al. (Paper 99-25, CSPG and Petroleum Society Joint Convention, Calgary, Canada, 1999), Butler et al. (J. Can. Pet. Tech., 39(1): 18, 2000). Examples of literature describing oil composition and viscosity gradients in heavy and bitumen reservoirs include: Larter et al. (2006), Head et al. (2003) and Larter et al. (2003).
There are other examples of processes that use steam or solvent with different well configurations to recover heavy oil and bitumen.
The literature contains many examples of in situ methods to recover heavy oil or bitumen economically yet there is still a need for more thermally-efficient and cost-effective in situ heavy oil or bitumen recovery technologies, especially when considering the vertical and areal variations of viscosity in the reservoir. There is disclosed herein a method to recover heavy oil or bitumen from a heterogeneous viscosity reservoir in a manner that is more cost-effective and thermally-efficient than existing methods.